Controlled descent caged ball bypass plunge

ABSTRACT

The present invention is related to a bypass plunger. The plunger includes a plurality of flow ports, a cage including a seat, a flow restriction member positioned within the cage, a choke passageway extending between the seat and a lower end of the plunger. The cage is located proximate the flow ports. The flow restriction member is movable between a seated position and an unseated position in response to formation contents flowed into the wellbore from a reservoir. The flow restriction member is the unseated position when the plunger descends down a wellbore and is the seated position when the plunger ascends in the wellbore. The flow ports, cage, and choke passageway are in fluid communication when the flow restriction member is in the unseated position. In the seated position, the flow restriction member is in physical contact with the seat. This configuration provides a bypass plunger with controlled descent.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application62/509,640, filed on May 22, 2017, the entirety of which is hereinincorporated by reference.

FIELD OF INVENTION

This invention relates to a plunger for lifting liquids upwardly in ahydrocarbon well. The invention relates to a by-pass plunger. Moreparticularly, the invention relates to controlled descent caged-ballbypass plunger and to methods for increasing the productivity of gaswells using said plunger.

BACKGROUND OF THE INVENTION

There are many different techniques for artificially lifting formationliquids from hydrocarbon wells. Reciprocating sucker rod pumps are themost commonly used because they are the most cost effective, all thingsconsidered, over a wide variety of applications. Other types ofartificial lift include electrically driven downhole pumps, hydraulicpumps, rotating rod pumps, free pistons or plunger lifts and severalvarieties of gas lift. These alternate types of artificial lift are morecost effective than sucker rod pumps in the niches or applications wherethey have become popular. One of these alternative types of artificiallift is known as a plunger lift, which is basically a free piston thatmoves upwardly in the well to lift formation liquids to the groundsurface. Typically, plunger lifts are used in gas wells that are loadingup with formation liquids thereby reducing the amount of gas flow. Afree piston should be understood to be a piston that is not attached toa reciprocating member, but rather relies on formation contents (e.g.,fluids and fluid pressure, gas and gas pressure, or a combinationthereof from a formation) to move the piston components. A plunger liftassembly and method for using such an assembly is disclosed in commonlyassigned U.S. Pat. Nos. 6,467,541 and 6,719,060, which are incorporatedherein by reference in their entirety.

Gas wells reach their economic limit for a variety of reasons. A commonreason is that the gas production declines to a point where theformation liquids are not readily moved up the production string to theground surface. Two phase upward flow in a well is a complicated affairand most engineering equations thought to predict flow are only roughestimates of what is actually occurring. One reason is the changingrelation of the liquid and of the gas flowing upwardly in the well. Attimes of more-or-less constant flow, the liquid acts as an upwardlymoving film on the inside of the production tubing string while the gasflows in a central path on the inside of the liquid film. The gas flowsmuch faster than the liquid film. When the volume of gas flow slows downbelow some critical value, or stops, the liquid runs down the inside ofthe flow string and accumulates in the bottom of the well.

If sufficient liquid accumulates in the bottom of the well, the well isno longer able to flow because the pressure in the reservoir is not ableto flow against the pressure exerted by the liquid column. In thatsituation, the well is said to have loaded up and died. Years ago, gaswells were plugged much quicker than today because it was not economicalto artificially lift small quantities of liquid from a gas well. Atrelatively high gas prices, it is economical to keep old gas wells onproduction. It has gradually been realized that gas wells have a lifecycle that includes an old age segment where a variety of techniques areused to remove liquids from the well and thereby prevent the well fromloading up and dying. A rule of thumb is that wells producing enough gasto have an upward velocity in excess of 10′/second will stay unloaded.Wells where the upward velocity is less than 5′/second will typicallyload up and die.

Free pistons or plunger lifts are a common type of artificial pumpingsystem to lift liquid from a well that produces a substantial quantityof gas. Conventional plunger lift systems comprise a piston that isdropped into the well by stopping upward flow in the well, as by dosingthe wing valve on the well head. The piston is often called a freepiston because it is not attached to a sucker rod string or othermechanism to pull the piston to the surface. When the piston reaches thebottom of the well, it falls into the liquid in the bottom of the welland ultimately into contact with a bumper spring, normally seated in acollar or resting on a collar stop. The wing valve is opened and gasflowing into the well pushes the piston upwardly toward the groundsurface, pushing liquid on top of the piston to the ground surface.

A major disadvantage of conventional plunger lifts is that the well mustbe shut in so the piston is able to fall to the bottom of the well.Because wells in need of artificial lifting are susceptible to beingeasily killed, stopping flow in the well has a number of seriouseffects. Most importantly, the liquid on the inside of the productionstring falls to the bottom of the well, or is pushed downwardly by thefalling piston. This is the last thing that is desired because it is thereason that wells load up and die. In response to the desire to keep thewell flowing when a plunger lift piston is dropped into the well,attempts have been made to provide valved bypasses through the pistonwhich open and close at appropriate times. Such devices to date arequite intricate and these attempts have so far failed to gain wideacceptance.

Recent development of multi-part plungers which may be dropped into awell while formation contents are flowing upwardly in the well are shownin U.S. Pat. Nos. 6,209,637, 6,467,541, and 6,719,060. In a recentdevelopment, taught in co-assigned and currently pending patentapplication Ser. No. 14/472,044, a flow restriction member is releasablyretained by a sleeve member such that the flow restriction member is notreleased from the sleeve member solely by the force of gravity. If theflow restriction member prematurely releases from the sleeve member,such as by a sudden decrease in fluid pressure (“lift”), the sleeve andflow restriction member will separately drop in the well until at somepoint they are reunited and begin the upward journey once again. In manyinstances, the separate free piston components are not reunited untilthey reach the bottom of the well at which time the process starts onceagain, thus losing valuable time and exposing the well to potentialfluid pressures that may cause the well to stop flowing.

In some of the prior art devices utilizing such a separate free pistonassembly, the components are latched together before beginning the liftportion of the process. Such latching presents problems that areovercome by the assembly described in patent application Ser. No.14/472,044. Specifically, the latching requires that the flowrestriction member be captured by a mechanical structure that hold theflow restriction member in place during the lift. Such latching can beconveniently implemented at the bottom of the well where other structureis available to prevent movement of the flow restriction member while itis being latched, but just the opposite is true if the joinder of theflow restriction member and the sleeve member are being joined at alocation above the bottom of the well. In such instances, the latchingmechanism can actually interfere with the seating of the flowrestriction member in the sleeve member and may result in the unwantedloss of time in joining the free piston members. The latching structurealso tends to be cumbersome to install and frequently wears out prior tothe useful life of the free piston assembly being completed.

For certain applications, the use of heavier, one-piece bypass plungersis preferred such as, for example, when sand causes premature wear onother types of plungers (e.g. padded plungers), in more dense fluidwells, during dean-out of a well, during operation in minimum bottomhole pressure, during operation in either high or low Gas Liquid Ratios(GLR). The use of one-piece bypass plungers circumvents long shut-intimes. Recent development of such one-piece plungers is shown in U.S.Pat. Nos. 7,438,125 and 9,068,443 as well as U.S. Pat. Publication No.2015-0300136. There remains, however, a need in the field for a simplerdesign single piece bypass plunger with fewer components that can fail,a plunger with a controllable fall rate to reduce excessive descentspeeds that can prematurely damage the plunger while still lifting alarge volume of fluids per run.

The current invention pertains to a one-piece, caged-ball by-passplunger that can have a controllable descent through a gas well.

SUMMARY OF THE INVENTION

The current invention provides an improved bypass plunger, the descentof which, down a hydrocarbon well, can be controlled by flow ports, acage, a caged ball, and ail internal choke passageway.

The current invention provides a controlled-descent, caged-ball bypassplunger having an upper end and a lower end. The upper end includes afishing neck to facilitate fishing the plunger out of a well and aplurality of flow ports. Located proximate the plurality of flow portsis a cage for housing a ball. The cage also includes a ball seatsituated on top of a choke passageway, wherein the choke passagewayextends from the ball seat to the lower end of the plunger.

The current invention also provides a controlled-descent, by-passplunger with a body having an upper end and a lower end; a cage having aball seat, a ball contained within said cage, wherein said ball ismovable between a seated position and an unseated position; a chokepassageway extending between said ball seat and said lower end of saidbody; one or more flow ports on the upper end of the plunger extendingthrough said body and in fluid communication with the choke passagewaywhen said ball is in the unseated position.

The current invention also provides a method for lifting fluids out of agas wellbore such that the method includes the steps of providing acaged-ball bypass plunger having a body with an upper end and a lowerend; a cage housing a ball positioned within said body, a ball seatconfigured to fit the ball wherein the ball is movable between a seatedposition and an unseated position; and a choke passageway extendinglongitudinally through the body between the ball seat and the lower endof the body wherein the choke passageway is closed when the ball is inthe seated position, controlling the rate of descent of the plungerthrough the gas well by selecting the size of the choke passageway,containing the ball within the cage in an unseated position therebyallowing gas flow through the choke passageway and out the plunger fromthe flow ports as the plunger descends in the wellbore, and liftingfluid above the plunger out of the wellbore with the ball in the seatedposition as the plunger ascends in the well.

In accordance with principles of the present invention, a one-piece,caged-ball bypass plunger is contemplated. The plunger may comprise abody having an upper end and a lower end, a plurality of flow ports onthe upper end of the body that extend through the body, a cage includinga seat, a flow restriction member positioned within the cage, and achoke passageway extending between the seat and the lower end of thebody. The cage may be located proximate the plurality of flow ports andconfigured to be in fluid communication with the plurality of flowports. The flow restriction member is movable between a seated positionand an unseated position such that the flow restriction member is theunseated position when the plunger descends down a wellbore and is theseated position when the plunger ascends in the wellbore. In the seatedposition, the flow restriction member s in physical contact with theseat. The choke passageway is in fluid communication with the cage andthe plurality of flow ports when the ball is unseated.

The number of the flow ports may be between 1 and 5. The flow ports mayhave a helical shape. The flow restriction member may be a ball.

The plunger may further comprise a fishing neck configured to facilitateretrieval of the plunger from the wellbore. The plunger may furthercomprise a plurality of exterior seal rings.

The body may include a first component and a second component. The firstcomponent may include the flow ports, the cage, and a fishing neck. Thesecond component may include the lower end. The first component mayinclude an opening to accommodate the second component. The secondcomponent may be configured to be inserted into the opening of the firstcomponent. The second components may further include a region having aplurality of threads, fasteners, or other mechanisms capable of affixingthe second component to a corresponding structure in the opening of thefirst component.

The second components may further include a region having a plurality ofthreads, fasteners, or other mechanisms capable of affixing the secondcomponent to the first component.

The body may be coated with Nickel Boron or Electroless-Nickel. Thelower end of the body may be configured to contact a bumper springassembly.

The flow restriction member may be configured to be movable in responseto formation contents flowing into the wellbore from a reservoir. Theplunger is configured to descend in the wellbore without shutting in thewellbore.

In accordance with principles of the present invention, a method forlifting formation fluid out of a wellbore is contemplated. The methodmay comprise introducing the plunger of claim 1 into the wellbore withthe lower end of the plunger entering the wellbore first, allowing theplunger to descent to a bumper spring assembly, and allowing the plungerto ascent in the wellbore in response to formation contents flowing intothe wellbore from a reservoir thereby pushing formation liquid above theplunger upward to a ground surface. The plunger may descent at a speeddetermined by the size and number of the flow ports.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a perspective view of one embodiment of a controlleddescent, caged-ball bypass plunger in accordance with the currentinvention, illustrating the upper and lower ends of the plunger, theflow ports and a ball caged inside the upper end below the fishing neck.

FIG. 2 is a cross-sectional view of the plunger shown in FIG. 1,illustrating the ball, ball cage, ball seat, and choke passageway.

FIG. 3 is a schematic view of a controlled descent, caged-ball bypassplunger in accordance with an embodiment of the current inventionwherein the plunger body includes a fishing neck, a plurality of flowports, and a plurality of exterior seal rings.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The current invention provides a controlled-descent, caged-ball bypassplunger having an upper end and a lower end. The upper end includes afishing neck to facilitate fishing the plunger out of a well. Betweenthe upper end and the lower end is a cage for housing a ball. The cagealso includes a ball seat situated on top of a choke passageway, whereinthe choke passageway extends from the ball seat to the lower end of theplunger. The caged ball and the seat are used to support a column offluid above the plunger during ascent of the plunger up a wellbore,thereby removing the fluid column. from the well and preventing the wellfrom loading up and dying. The diameter of the choke passageway may beselected to control the descent speed of the plunger when fallingthrough the well to a bumper spring positioned lower in the wellbore.The size and number of the flow ports may also be selected to controlthe descent speed.

Referring to FIG. 1, a one-piece, caged-ball bypass plunger 100 isillustrated. The plunger 100 comprises a cylindrical body 105 that hasan upper end 110, a lower end 115, and a plurality of exterior sealrings 120. As previously indicated, the upper end 110 of the body 105may comprise a fishing neck 125 to facilitate the retrieval of theplunger 100 from the wellbore when necessary. The fishing neck 125allows an operator o retrieve the plunger 100 without relying on theformation contents (i.e., fluid, gas, or pressure) flowing into thewellbore from the reservoir. For example, an operator can fish out theplunger when the amount of formation contents is inadequate to transportthe plunger to the ground surface, when the amount of the formationcontents is sufficient to transport the plunger to the ground surfacebut the operator wishes to retrieve the plunger sooner or the plunger isstuck in the wellbore, or for other reasons. The fishing neck 125includes structures allowing retrieval of the plunger by tools and is acomponent known in the art. The fishing neck 125 is adjacent to the cage135. The cage 135 and the ball 140 are located between the fishing neck125 and the seal rings 120. The cage 135 and ball 140 may also bearranged in other locations.

The upper end 110 of the body 105 also includes a plurality of flowports 130. The size and the number of ports 130 can vary, and thisvariation is well understood by those of skill in the art so as toaccommodate the flow of fluid or gas through the plunger 100 as theplunger 100 descends in the wellbore. The larger the port 130 or numberof ports 130, the more fluid or gas can flow through the ports 130without creating unnecessary pressure drop. It is contemplated that thenumber of ports 130 per plunger 100 can be 1 or up to 5 ports. As shown,the ports 130 take the shape of a helical groove, but other shapes anddimensions are also contemplated. For example, a port may be 0.375″ indiameter and may have a length of 0.91″, 1.17″, 1.47″, or 1.73″, etc. asappreciated by a person of skill in the art. The port size, number, andshape can be selected and assembled to a user's request. Depending onthe well conditions, an operator can also choose between a variety ofplungers with different port sizes. The operator can also choose betweenheavier or lighter plungers depending either on the length of theplunger body or on the material used so as to further optimize for agiven well condition. Different materials used may include 4140 steel,stainless steel or titanium which is much lighter. The plungers may alsobe coated with Nickel Boron or Electroless-Nickel for increasedcorrosion-resistance and longevity. The preferred embodiments of theplunger 100 of the current invention can be designed for 2.0625″, 2,375″and 2.875″ O.D. production tubing strings.

As shown in FIG. 2, the body 105 further comprises a cage (or chamber)135, a ball 140 within the cage 135, a ball seat 145, and an internalflow/choke passageway 150 that runs from the ball seat 145 and to thelower end 115 of the body 105. In a preferred embodiment, the balldiameter is 1 inch. However, ball diameters in the range of ¾″ through1¼″ are also in accordance with the current invention. Other ranges arealso contemplated. The flow ports 130 at the upper end 110 of theplunger 100 extend all the way into the ball cage 135 and are in fluidcommunication with the cage 135. The flow ports 130 are in fluidcommunication with the cage 135 regardless whether the ball 140 is inthe seated position or the unseated position. The internal diameter ofthe choke passageway 150 can be varied to control descent down awellbore. The smaller the internal diameter of the choke passageway 150,the slower the descent. The larger the internal diameter of the chokepassageway 150, the less restriction to flow and the faster the descentin the well. The choke passageway diameter can be 5 mm, 6 mm, 8 mm, 10mm or as would be contemplated by one of skill in the art. In apreferred embodiment, the diameter of the choke passageway 150 is 0.315(or 8 mm). The width or diameter 52 of the choke passageway 150 can besmaller than that of the cage 135 (FIG. 2, 154). The length of the chokepassageway 150 can also be adjusted depending on the application.

The ball 140 is movable between a seated position and an unseatedposition. FIG. 2 shows the ball 140 in the unseated position. There canbe numerous unseated positions in that the ball 140 is considered as inthe unseated position when the ball 140 leaves the ball seat 145 or isnot in physical contact with the ball seat 145. The ball 140 can move toany location or unseated position in the cage 135 when the ball 140leaves the ball seat 145. The ball 140 is confined in the cage 135 andthe cage 135 is defined by the upper end 110 and the ball seat 145. Theball 140 is prohibited from escaping the cage 135 or the plunger 100.This configuration allows deploying only one piece of plunger into thewellbore to remove formation liquid and eliminates the need toseparately introduce another plunger or ball. The body 105 and the ball140 can be dropped into the wellbore simultaneously. The ball 140 ismovable in the cage 135 in response to formation contents flowing intothe wellbore from a reservoir. The ball 140 may be configured with aweight and size to determine an amount of fluid, gas, or pressurerequired to unseat the ball 140. The ball 140 is not mechanicallylatched to the cage 135, the upper end 110, or the lower end 115. insome embodiments, the cage 135 and the ball 140 may be configured in amanner such that the ball 140 can be unseated by a person holding theplunger 100 horizontally or by tilting the lower end 115 higher than theupper end 110 from the horizontal position.

The caged ball 140 and the seat 145 are used to lift a column of fluidabove the plunger 100 during ascent up a wellbore. The plunger 100 isdeployed into the wellbore with the lower end 115 entering the wellborefirst. As the plunger 100 descends in a well bore, gas or liquid flowinginto the wellbore from the reservoir passes through the choke passageway150 and pushes the ball 140 upward from its seat 145 (unseated) therebyallowing the choke passageway 150 to fluidly communicate with the cage135 and the ports 130 in the upper end 110 of the plunger 100. Thisallows the flowing gas and/or liquids to bypass the plunger 100 duringdescent so that the well does not need to be shut in while the plunger100 falls to the bottom of the well. Because of this bypass feature, thewell avoids lengthy shut-in periods thereby increasing the gasproduction of the well. Once the plunger 100 falls into the formationliquid in the bottom of the well and lands on the bumper spring assembly(with the lower end 115 contacting the assembly), the weight of theaccumulated liquid above the plunger 100 (formation liquid above theupper end 110 as a result of falling into the formation liquid) willcause the caged ball 140 to sit on the ball seat 145 thereby closing thechoke passageway 150. Pressure will build under the plunger 100 (underthe lower end 115) until the pressure is sufficient to lift the closedplunger 100 and the column of liquid above it out of the well. Once theplunger 100 arrives at the ground surface and the fluid column isproduced out of the well and down the surface flow line leading from thesurface lubricator, the ball 140 is no longer held in the seatedposition and the plunger 100 can be dropped back into the flowingwellbore. Although FIG. 2 illustrates a ball, the ball can be other flowrestriction member having other structure, shape, or size. The cage 135can also have other structure, shape, or size to accommodate the flowrestriction member.

FIG. 2 also shows that the body 105 comprises a first component (uppercomponent) and a second component (lower component). The first componentmay include the upper end 110 (which includes the fishing neck 125, flowports 130, and the cage 135) and the external seal rings 120. The secondcomponent may include the lower end 115. In some embodiments, the rings120 can be part of the lower component. For ease of manufacture and/orinstallation of the ball into the cage, the first component and thesecond component may be two separate pieces joined together. The firstcomponent, such as a sleeve, may include an opening 160 to accommodatethe second component and the second component may be inserted into theopening 160. The choke passageway 150 may be located in the interior ofthe lower component and the ball seat 145 may be situated at one end ofthe choke passageway 150 or the second component. The other end of thesecond component (i.e., the lower end 115) is configured to contactbumper a spring assembly. The second component may include a region 155to engage with the first component. The region 155 may include aplurality of threads, fasteners, or other mechanisms that canmechanically affix the two components together. The region 155 preventsseparation of the first component and the second component. The firstcomponent may include a corresponding structure to engage with theregion 155. In one embodiment, the two components can be screwedtogether and spot welded at region 155. In some embodiments, part of thechoke passageway 150 may be in the first component and part of the chokepassageway 150 may be in the second component. The entire chokepassageway 150 can be formed when the first component and the secondcomponent are joined together via the region 155. In that situation, theball seat 145 is also located in the first component since the portionof the choke passageway 150 in the first component is the structure thatprovides the ball seat 145. The second component may end at a tip of theregion 155 into the first component. Other configurations are alsocontemplated.

Referring to FIG. 3, the body 105 of the plunger 100 includes aplurality of exterior rings 120 (also referred to as seal rings) andgrooves 122 (between the rings 120) that provide a functional sealbetween the tubing and plunger and help create a sealing turbulent gasflow that prevents liquids being lifted by the plunger from falling pastthe plunger(or downward toward the spring assembly) during the ascentphase in the well.

During operation, the plunger ball 140 is either in the seated orunseated position. The ball 140 is in the unseated position when theplunger is travelling down the wellbore. When the ball 140 is in theseated position on the ball seat 145 on top of and closing off the chokepassageway 150, the plunger 100 is capable of lifting liquids andtravelling upwards in the well. When the plunger 100 falls down thewellbore, the ball 140 is unseated, and flowing wellbore gas and liquidscan bypass through the plunger 100. Gas flowing in the well beneath theplunger (beneath the lower end 115) will flow through the chokepassageway 150, the cage 135, the ports 130 (in that order) and towardthe ground surface of the well as the plunger 100 falls until it hits alower bumper assembly located near the bottom of the well. Gas from theformation flow into the wellbore beneath the plunger 100, until enoughpressure is built that lifts the plunger 100 and any accumulated liquidabove the plunger (above the upper end 110) upwards in the well. A smallamount of gas also flow around the external seal rings of the plungercreating a turbulent sealing flow that prevents liquids above theplunger from falling between plunger body 105 and the well tubing as theplunger 100 ascends in the wellbore.

The invention herein also provides a method for lifting fluids out of ahydrocarbon wellbore that includes providing a controlled descentcaged-ball bypass plunger having the characteristics described above andthe features illustrated in FIGS. 1-3. The method would be understoodfrom the above and the overall disclosure.

Although this invention has been disclosed and described in itspreferred forms with a certain degree of particularity, it is understoodthat the present disclosure of the preferred forms is only by way ofexample and that numerous changes in the details of construction andoperation and in the combination and arrangement of parts may beresorted to without departing from the spirit and scope of the inventionas hereinafter claimed. Broader, narrower, or different combinations ofthe described features are contemplated, such that, for example featurescan be removed or added in a broadening or narrowing way.

What is claimed is:
 1. A plunger comprising: a body having an upper endand a lower end; a plurality of flow ports on the upper end of the body,the flow ports extending through the body; a cage including a seat, thecage being located proximate the plurality of flow ports and configuredto be in fluid communication with the plurality of flow ports; a flowrestriction member positioned within the cage, wherein the flowrestriction member is movable between a seated position and an unseatedposition such that the flow restriction member is in the unseatedposition when the plunger descends down a wellbore and is in the seatedposition when the plunger ascends in the wellbore, and wherein in theseated position the flow restriction member is in physical contact withthe seat; and a choke passageway extending between the seat and thelower end of the body, wherein the choke passageway is in fluidcommunication with the cage and the plurality of flow ports when theball is unseated.
 2. The plunger of claim 1, wherein the number of theflow ports is between 1 and
 5. 3. The plunger of claim 1, wherein theflow ports have a helical shape.
 4. The plunger of claim 1, wherein theflow restriction member is a ball.
 5. The plunger of claim 1, furthercomprising a fishing neck configured to facilitate retrieval of theplunger from the wellbore.
 6. The plunger of claim 1, further comprisinga plurality of exterior seal rings.
 7. The plunger of claim 1, whereinthe body includes a first component and a second component, the firstcomponent includes the flow ports, the cage, and a fishing neck, and thesecond component includes the lower end.
 8. The plunger of claim 7,wherein the first component includes an opening to accommodate thesecond component.
 9. The plunger of claim 8, wherein the secondcomponent is configured to be inserted into the opening of the firstcomponent.
 10. The plunger of claim 9, wherein the second componentfurther includes a region having a plurality of threads, fasteners, orother mechanisms capable of affixing the second component to acorresponding structure in the opening of the first component.
 11. Theplunger of claim 7, wherein the second component further includes aregion having a plurality of threads, fasteners, or other mechanismscapable of affixing the second component to the first component.
 12. Theplunger of claim 1, wherein the body is coated with Nickel Boron orElectroless-Nickel.
 13. The plunger of claim 1, wherein the lower end ofthe body is configured to contact a bumper spring assembly.
 14. Theplunger of claim 1, wherein the flow restriction member is configured tobe movable in response to formation contents flowing into the wellborefrom a reservoir.
 15. The plunger of claim 1, wherein the plunger isconfigured to be deployed in the wellbore without shutting in thewellbore.
 16. A method for lifting formation fluid out of a wellbore,comprising: introducing the plunger of claim 1 into the wellbore withthe lower end of the plunger entering the wellbore first; allowing theplunger to descent to a bumper spring assembly, wherein the plungerdescents at a speed determined by the size and number of the flow ports;and allowing the plunger to ascent in the wellbore in response toformation contents flowing into the wellbore from a reservoir therebypushing formation liquid above the plunger upward to a ground surface.17. A method for lifting formation fluid out of a wellbore, comprising:introducing the plunger of claim I into the wellbore with the lower endof the plunger entering the wellbore first; allowing the plunger todescent to a bumper spring assembly, wherein the plunger descents at aspeed determined by the size of the choke passageway; and allowing theplunger to ascent in the wellbore in response to formation contentsflowing into the wellbore from a reservoir thereby pushing formationliquid above the plunger. upward to a ground surface.